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The Bullfrog Was an Unusual Probe, TOTAL Explains

French major TOTAL has given the full story of the Brulpadda discovery, offshore South Africa.

Brulpadda is an Afrikaans word meaning Bullfrog, the large amphibian with a deep roaring sound, and one of Southern Africa’s most widespread frog species.

“It was a very bold technical well,” Enzo Insalaco, the company’s Vice President Exploration Africa, told delegates at the Africa Oil Week in Cape Town, in early November 2019. “Many people may not realise that the well was actually drilled on 2D” (two dimensional seismic data). “It is a deep offshore well, so drilling on 2D was a very bold move. But given our understanding of the basin and the innovations we did on the operations, this well could be drilled safely and successfully on 2D”.

Insalaco enthused that the Brulpadda probe was within budget, within time and in terms of Non Productive Time (NPT): “We have about 3% of NPT and 3% waiting on weather. If you consider the conditions, that is fantastic operational performance. We drilled the well to the main reservoir log and then we went down to a deeper reservoir”, he explained, to an attentive audience of C-Suite types.

“We did extensive logging records, took samples of fluid, reservoir and source rock. It was a fantastic result in terms of operational performance and data acquisition. It is a gas and condensate and oil discovery, both traces were found. The reservoirs were well developed with good fluid and reservoir properties. You could not really wish for more information from an exploration well. That data acquisition has really put us in a great position going forward to be able to accelerate the next level and the evaluation.”

The VP said that TOTAL finished its P&A (plug and abandon) of the well in the first week of February. “The rig moved offsite the middle of February, and the first 3D seismic shot was done on the 14th of March. A month between the first shot of seismic and the end of the work which is a fantastic performance.

“We also fast tracked the seismic acquisition, so we could start looking at the potential on the new data by June of this year and that allows us, together with the information that we collected, to fast track well evaluation and put us into position to commission the rig and be able to drill early next year. Doing as many processes in parallel allowed us to save 18 months to two years in the well programme and I don’t think we can compress that timeline anymore, given the operational constraints and the operational windows for the seismic acquisition.”

Brulpadda is located on Block 11B/12B in the Outeniqua Basin. It encountered 57 metres of net gas condensate play in Lower Cretaceous reservoirs. Following the success of the main objective, the well was deepened to a final depth of 3,633 metres and has also been successful in the Brulpadda-deep prospect.

For TOTAL, Brulpadda was certainly a high impact well for opening up what they believe is a significant petroleum basin.


TGS-PetroData Acquires Data, Ready For ‘Forthcoming’ Licencing Round

Chief Executive Officer of PetroData

TGS-PetroData is to commence a regional Multi beam and Seafloor Sampling (MB&SS) Programme, covering 80,000 square kilometres of both allocated and non-allocated blocks from offshore to deep offshore Niger-Delta, in December 2019.

The new survey will capture 200 core locations and provide crucial de-risking of the petroleum system, “to help better inform exploration and appraisal decision making”, says Wole Shebioba, Chief Executive Officer of PetroData, who serves as Director of administration for the project.

PetroData, originally a data warehouse company, went into partnership, six years ago, with TGS, the Norwegian player and global specialist in multi client data acquisition and marketing. The resulting incorporated Joint Venture, TGS-PetroData Services Ltd, received the approval of the Department of Petroleum Resources, the Nigerian regulatory agency, to conduct the programme.

There is a further plan to acquire two dimensional (2D) regional well tie data; that is tying most of the deep water wells in Nigeria with 2D seismic lines. And there is also a regional reprocessing project.

“We have extensive 2D seismic data which was acquired between 1998/1999 by Veritas. We have almost completed the reprocessing of the data” Shebioba explains..

“With these three packages, I believe that we are ready for the proposed licensing round by the government”, Shebioba anticipates. “When it takes place, there is going to be at least new data for investors to see. But of course, you know that we are doing all these in partnership with the DPR”.

TGS-PetroData had a roadshow around Nigeria with the reprocessed data on projects NG02 survey  and NGRE19 survey. It presented it to the companies it thinks might be interested, especially the five majors who operate in Nigeria (ExxonMobil, TOTAL, Shell, Chevron, ENI (Agip) “and to a large extent, they were happy with what they’ve seen”, Shebioba says.

“The whole idea data is for de-risking a prospect and so, the more data you have the more confident you are about where you want to drill and the likelihood of getting oil. So companies and the people that understand the business of exploration have all kinds of data, as much as you can get”.

There’s nothing like too much data, argues Shebioba, himself a trained geophysicist of 33 years post-graduation experience, who spent his first 11 years working for Shell. ”When a data you have here is saying this and another you have is not consistent with that, you would have another one that would tell you to confirm what the first one is saying.

You are confirming and confirming and confirming until you are absolutely sure. Because you have all kinds of data, you can de-risk and say yes, what I am seeing is correct or not. But, we lack data in Nigeria, we lack new data and everybody have been shouting that there have not been investment in new exploration in the country “.




Ghana’s Springfield makes a Discovery in Deepwater

By John Ankromah

Ghanaian homegrown independent, Springfield Exploration and Production has discovered oil in its very first attempt at drilling.

The company encountered 50 metres net light oil pay in high quality Cenomanian sand stones, in the West Cape Three Points Block 2 (WCTP2)  Offshore Ghana, according to very impeccable sources at the country’s Ministry of Energy & Petroleum. The gross thickness of the hydrocarbon column is 65 metres. Afina 1 is located in a water depth of 1,030 metres.

The well, spud on October 7th, 2019, is being drilled drillship Stena Forth.

A release will be made by Springfield itself in the coming days.

Afina-1 is the first of two exploratory wells that Springfield proposes to start with on the asset. The second is Oak-1.

WCTP2 was carved out of the West Cape Three Points block, operated by Kosmos Energy, following the delineation of the Jubilee unitisation area. The block was subsequently awarded to Springfield E&P for a seven year exploration period from July 2016.

WCTP2 is situated between the Jubilee field (90,000BOPD) and Sankofa (30,000BOPD) field and is immediately north of Aker Energy’s Pecan, Hickory, Almond, Paradise and Beech discoveries.

The latter extends into the WCTP2 block. The licence consists of two components, an exploration component and an appraisal/development component for the existing discoveries, Odum and Banda.

Springfield operates the WCTP2 with 84%, with the Ghana National Petroleum Corporation (GNPC) having an 11% carried interest.

GNPC’s designated operating arm, the GNPC Explorco, also holds a 5% carried interest.

Springfield has, by merely spudding the well, achieved history as the first home-grown, African owned E&P operator to spud a well in a new deepwater licence.

With this discovery, it secures its place.


Is Namibia Stuck in the “Hoping” Mode?

By Toyin Akinosho, Publisher.

In the frontier, the world waits for a big find…In the proven, the Kudu field looks forward to bankability..

Namibia is in that space again.

Between a wave of exploratory drilling activity and the preparatory stages to the next big probe.

Drilling is the “rock star” event of the exploratory work programme in the oil industry. Seismic acquisition, processing and interpretation are all crucial, as are other cross disciplinary geoscience work that preface drilling. They determine the success of a well, but they don’t show up as headline stories.

Which is why, after two highly anticipated wells turned out disappointing in late 2018, the focus has been not so much on the post well interpretation of these probes, or the basin analysis studies actively going on in the country, but on the wells that have been announced for 2020-2021 drilling.

Neither Tullow Oil, who encountered non-commercial hydrocarbons at its Cormorant-1 exploration well in the Petroleum Exploration Licence (PEL)-37, nor Chariot Oil& Gas, who reported finding water-bearing reservoirs in the exact place it was expecting oil in Prospect S, in PEL 71, is looking forward to any drilling in the next two years.

But everyone is anticipating TOTAL’s planned Venus-1 well, in ultra-deep offshore Block 2912.

Claims that Venus might emerge the largest discovery on the continent in the last 10 years are “supported” by a widely publicised seismic profile showing an extensive basin floor fan and a mapped surface indicating an Amplitude Versus Offset (AVO) supported direct hydrocarbon indicator (DHI), said to be similar to Brazil’s Marlin discovery. The problem with the Marlin comparison is that Namibia is not exactly conjugate with Brazil the way Angola is and the Angolan “mirrors” of Brazilian plays that have been drilled so far have been dusters.

Unlike most African countries without a single molecule of hydrocarbon in production, Namibia somehow keeps in the news, and manages to have hosted the big oil majors all through the last 45 years.

ExxonMobil signed agreements to extend its footprint in the country last April. It inked deals with the government and the National Petroleum Corporation of Namibia (NAMCOR) for blocks 1710 and 1810, and farm-in agreements with NAMCOR for blocks 1711 and 1811A. In addition to the 40% interest in the 11,500 square kilometre PEL 82 license, which it already had, ExxonMobil will operate blocks 1710 and 1810 and hold a 90% interest; NAMCOR will hold a 10 percent interest. ExxonMobil will assign 5% of its interest to a local Namibian company. ExxonMobil will be operator of blocks 1711 and 1811A, and will hold an 85% interest. NAMCOR will retain a 15% interest.

One key new entrant to watch is Kosmos Energy, the American junior with a record of wildcat exploration successes in Africa in the last 12 years. In October 2018, Kosmos entered into a strategic exploration alliance with Shell to jointly explore in Southern West Africa, with initial focus on Namibia, where Kosmos has acquired interest in Shell-operated block PEL 39. As part of the alliance, the two companies will also jointly evaluate opportunities in adjacent geographies. The block covers an area of approximately 12,000 square kilometres in water depths ranging from 250 to 3,000 meters. In January 2019, Kosmos completed a 3D seismic survey covering approximately 6,000 square kilometres. Processing of this data is currently underway. The company is compiling an inventory of prospects on the license while integrating the new three dimensional (3D) seismic data in its geological evaluation during 2019. It hopes it may drill a well as early as 2020.

Kudu Scrambles ….

The Kudu Gas to Power project has at least 18 months to go before all the pieces can come together to make it the sort of bankable proposal that gets the Final Investment Decision.

The project, in the current iteration, is to valourise the 1Trillion standard cubic feet Kudu gas field, and use some of the gas to generate electricity from a 475 MW plant. BW Offshore concluded its farm into the Kudu field acreage in February 2017, taking a 56% stake with the state hydrocarbon company NAMCOR holding a 44% stake in the upstream and midstream segments of the project. The state power utility Nampower, with its partners, will install the power plant, offtake the gas and convert it to electricity. But neither state owned enterprise has been able to get hold of their share of financing the project,

NAMCOR was hoping that BW Offshore would carry it by paying its 44%, after the ministerial consent had been granted. But that has not happened. NAMCOR is now willing to fund 10% and find willing investors for the remaining 34%. Downstream, the NamPower is challenged in raising finance for its 51% share of the power generation side of the project.

The invoice for the Kudu Power Station is about $749Million of which 75% would be raised as debt (limited recourse). The gas field development is expected to cost $1.15illion (70:30 debt/equity), So the entire funding to get the project started is slightly less than $2Billion.

“Coordinating three integrated projects with a combined cost in excess of $1.9 Billion does not happen over-night!”, says Immanuel Mulunga, NAMOCOR’s Chief Executive Officer. “Namibia’s GDP is around $13Billion and it has taken several years to get the Kudu project to the point where all the technical/commercial hurdles have been overcome”.

Although the argument has been that the less money from the treasury goes into the project the better, in order not to burden the tax payer, the fact is that project sponsors need assurance from Government that the electricity bought by public institutions will be paid for. There have also been calls for modification of the single buyer model for the project, which would have seen all the electricity produced sold to NamPower, to a multi-buyer model, including a private energy supply concept that would most likely see Kudu Gas also supply electricity directly to private buyers.

In any case, for now, Kudu Gas To Power isn’t yet at a stage that a Final Investment Decision can happen.


Amni Progresses Tubu Development Drilling, Eyes First Oil 2020

Amni International was drilling ahead in mid-October on a location in the Tubu field in Oil Mining Lease (OML) 52, in shallow water eastern Nigeria.

It is the first of eight development wells. The rig is Triident VIII, operated by Shelf Drilling.

Amni purchased Chevron’s 40% stake in OML 52 in 2014. The American major had drilled seven wells; the discovery well and six appraisals. In 2013, Chevron was carrying P1 reserves of 142MILLION barrels of Oil Equivalent.

Amni had its field development plan approved by the Department of Petroleum Resources and plans to drill eight wells to drain the field in the first phase, which is oil development. Some of the production facility is being constructed outside Nigeria. The well head platform will be tied into Amni’s existing Ima facilities, 10 kilometres to the south on OML 112.

It’s not clear what volume of oil per day is envisaged, but the oil development is the first of two phases. Gas development is the second phase of the project. For the first phase, associated gas will be extracted at Ima, and re-routed to Tubu for re-injection. Liquids will be offloaded at the same FPSO.

Armour Suspends Seismic Acquisition in Uganda

By Paul Njoroge

Australian explorer, Armour Energy, has suspended work on two dimensional (2D) Seismic data acquisition in the Kwanytaba block onshore Uganda.

Completion of that 2D seismic survey was part of the Minimum Work Program to be completed by the Company by 13 September 2019, pursuant to the Production Sharing Agreement for Petroleum Exploration, Development and Production in the Republic of Uganda By and Between The Government of the Republic of Uganda and Armour Energy Ltd for Kanywataba Contract Area dated 14 September 2017.

The Company wrote to the Minister in mid- October 2019, declaring that it was suspending work on the 2D seismic survey as a result of an event of Force Majeure (as defined under the PSA). Armour stated that recent severe storms and flood in the Kanywataba Contract Area, have made it practically impossible for vehicles to traverse many of the access roads in the Contract Area, so that the Company’s contractor cannot complete the line clearing, surveying or drilling activities necessary to complete the 2D seismic survey.

Armour ought to have finalised the seismic survey acquisition earlier, as per the terms of the licence, even before these recent weather challenges. But the company says that “due to a series of delays beyond the control of the Company, the Company was unable to complete the 2D seismic survey by 13 September 2019”. The Government of Uganda has made it a condition of the renewal of EL 1/2017 that the Company complete the 2D seismic survey during the second term of the licence.

Armour says that as at the date of this announcement, approximately 89% of the land clearing (being 96.06 km) and 86% of the surveying (being 93 km) necessary to carry out the 2D seismic survey has been completed. Also, 810 boreholes (into which the seismic charges are to be placed), or 37.5% of the total, have been drilled.

“Given the amount of work that was completed before work was suspended, the Company anticipates that it should be able to complete the 2D seismic survey relatively quickly once it resumes work”, Armour explains. The company says it is “advised that water levels will likely have sufficiently subsided by early 2020, to allow work to recommence”.


NNPC’s Announcement of Kolmani 2 Discovery Is Vague on Details

The Nigeria National Petroleum Corporation announced the discovery of hydrocarbons in Kolmani River 2, an appraisal well drilled in Bauchi, in the Upper Benue Trough, Gongola Basin, but was extremely vague on details.

The statement, released by its corporate affairs department, did not state the net or gross hydrocarbon footage in any reservoir(s).

The press release said the well was drilled with “IKENGA RIG 101” to a total depth of 13,701feet, encountering oil and gas in several levels, meaning that hydrocarbon was encountered in several reservoirs more than the only reservoir that encountered gas in the Kolmani 1.

“A Drill Stem Test (DST) is currently on-going to confirm the commercial viability and flow of the Kolmani River reservoirs”, the company said.

The part of the statement that could have passed for a useful status update of the probe was couched in poor professional language:  “On Thursday 10th October, 2019, at 18:02hours, one of the reservoirs was perforated and hydrocarbon started flowing to the well head at 21:20hours in which the gas component was flared to prevent air charge around the Rig”.

What does that mean?

For a well that had been spud as far back as February 2019, a more standard report was expected.

NNPC added that “Preliminary reports indicate that the discovery consists of gas, condensate and light sweet oil of API gravity ranging from 38 to 41 found in stacked siliciclastic cretaceous reservoirs of Yolde, Bima Sandstone and Pre-Bima formations”.

The company said it acquired 435.54km2 of three dimensional (3D) Seismic Data over Kolmani Prospect in the Upper Benue Trough, Gongola Basin. This was to evaluate Shell Nigeria Exploration and Production Company (SNEPCo) Kolmani River 1 Well Discovery of 33 BCF and explore deeper levels.

The Corporation has also acquired additional 1183km2 of 3D seismic data over highly prospective areas of Gongola Basin with a view to evaluating the full hydrocarbon potential of the Basin. NNPC has deployed world class cutting-edge technologies including Surface Geochemistry, Ground Gravity/Magnetic, Stress Field Detection, Full Tensor Gradiometry aerial surveys to de-risk exploration in the frontier basins.

The NNPC plans to drill additional wells for full evaluation of the hydrocarbon volume in the Gongola Basin.


Ghanaian Minnow Spuds Deepwater Well

Ghanaian independent, Springfield E&P,has spud its first well on the West Cape Three Points (WCTP) Block 2 acreage, in the country’s prolific Tano Basin.

The drillship Stena Forth spud Afina-1 at 6.50pm, October 7th, 2019, according to Kevin Okyere, Springfield’s founder and CEO.

Afina-1 is the first of two exploratory wellsthat Springfield proposes to start with on the asset. The second is Oak-1.

Springfield doesn’t say what water depth Afina is located and has also not disclosed the proposed Total Depth. The block itself, WCTP2, lies between 100metre and 1,700metre water depths. Deepwater starts from the 200metreisobath.

WCTP2 was carved out of the West Cape Three Points block, operated by Kosmos Energy, following the delineation of the Jubilee unitisation area. The block was subsequently awarded to Springfield E&P for a seven year exploration period from July 2016.

WCTP2 is situated between the Jubilee field (90,000BOPD) and Sankofa (30,000BOPD) field and is immediately north of Aker Energy’s Pecan, Hickory, Almond, Paradise and Beech discoveries.

The latter extends into the WCTP2 block. The licence consists of two components, an exploration component and an appraisal/development component for the existing discoveries, Odum and Banda.

Springfield operates the block with 82%. The two partners, state hydrocarbon companies GNPC and GNPC Explorco hold 8% and 10% equity respectively. They are both carried.

Springfield has, by merely spudding, achieved history as the first home-grown, African owned E&P operator to spud a well in a new deepwater licence.

Other African owned E&P companies with licences in Ghana include Amni, Oranto, Brittania U and Sahara. They were all awarded their different blocks in the country before Springfield E&P but have not announced any concrete drilling plans.

Africa Oil+Gas Report’s earlier story indicated that Springfield’s first well would be Oak-1. Both prospects are to be tested on the basis of interpretation of an 800 sq kilometre, three dimensional (3D) seismic data, acquired by PGS and paid for by Springfield, in 2017.


BW Gets More than It Bargained For

BW Energy’s side-track appraisal of the Hibiscus Updip oil discovery in Gabon has exceeded the company’s expectations to the extent that it is now expanding the initial hook up plan.

The company’s ‘Phase 3 development plans’ to tie the nearby Ruche and Ruche NE fields back to the Adolo FPSO are now being expanded to include a possible fast-track development of the discovery.

The estimate of gross recoverable oil at Hibiscus Updip, computed from the original wellbore and sidetrack is between 40 and 50Million barrels, according to reports widely shared with the public.

“This successful well enables us to further de-risk Gamba prospectivity in the Hibiscus area where we see significant additional potential”, says Panoro Oil, a minority partner in the asset and the project. “We are extremely pleased with the continued drilling success at Dussafu, and now look forward to the commencement of the production drilling phase at Tortue”.

The DHIMB-1 well was initially drilled in 116 metres of water to a vertical depth of 3,538 metres. On August 30, 2019, an oil discovery was announced in the pre-salt Gamba reservoir with plans to drill a sidetrack to appraise the extent of the Hibiscus Updip discovery.

The well was drilled in the northwest of the structure to test the lateral extent and structural elevation of the Gamba reservoir. The sidetrack was drilled to a Total Depth (TD) of 3,500 metres, (3,049 metres True Vertical Depth Subsea (TVDSS)) approximately 1.1 km from the original wellbore and found a 33 metre oil column with 26 metres of oil pay in the Gamba reservoir with better reservoir character and a similar fluid level to that encountered in the vertical well, DHIBM-1.

Further upside potential exists in the wider Hibiscus area which will be the focus of future exploration drilling.


Accra based Springfield on a Historic Deep-water Journey

By Toyin Akinosho, Publisher

In a matter of weeks, Springfield E&P will be the first home-grown, African owned E&P operator to spud a well in a new deepwater licence.

Its planned drilling of Oak-1, for which it had contracted the Stena Forth drillship, is significant history making.

The 11 year old company plans to follow up the well with another, the Afina-1, both of them in West Cape Three Points (WCTP) Block 2, offshore Ghana.

By all accounts Springfield will be drilling the wells as a full blown operator.

Oak-1 is on trend with the Beech structure, on which Hess Corp. discovered oil in Beech-1 in 2013, in 1,713 metres of water.

Both prospects are to be tested on the basis of interpretation of an 800 sq kilometre, three dimensional (3D) seismic data, acquired by PGS and paid for by Springfield, in 2017.

It will not be the first time that a company owned by African businessmen would drill, or be part of drilling, in deepwater, but there’s a context.

“Other African owned E&P companies with licences in Ghana, including Amni, Oranto, Brittania U and Sahara, were all awarded their different blocks in the country before Springfield.”

The Nigerian founded Erin Energy, now in bankruptcy, was drilling wells in over 400 metres of water offshore western Niger Delta. It was running a 40,000BOPD Floating Production Storage Offshore (FPSO) facility, the Armada Perdana, until it stopped being a going concern in mid-2018. Its licence to OML 120 was revoked by the government in June 2019.

London listed Afren discovered the Ogo field in 2013, said to be one of the largest discoveries in the world in that year, with, in part, funding raised by LEKOIL, the AIM listed firm founded by a Nigerian entrepreneur.

But Erin Energy (formerly Allied Energy, a subsidiary of Camac, and listed in NYSE Amex), was an operator by default; it came from being a non-operating partner to Statoil, which discovered the asset, Oyo field, in 1995, and ENI, which put it on stream in 2010 and was producing it until it pulled out of that asset. At no time from discovery to commissioning was Erin in operational charge of Oyo field.

LEKOIL, meanwhile, was, on Ogo discovery, also a non-operating partner to Afren, a company founded by a diverse mix of nationalities and which also has ceased to exist.

Springfield was awarded the WCTP Block 2 in 2016, with Ghana National Petroleum Corporation (GNPC) and its operating subsidiary, GNPC Explorco, as carried partners.

Other African owned E&P companies with licences in Ghana include Amni, Oranto, Brittania U and Sahara. They were all awarded their different blocks in the country before Springfield but have not announced any concrete drilling plans.

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